While much of the country has either deployed or is in the process of deploying AMI technology, there are still tens of millions of meters that have not yet been transitioned from legacy solutions. This includes utilities that have continued to maintain and operate dated, manual “walk-up” meter reading, as well as those that made the transition to AMR, or “drive by” meter reading in the late 90s and early-2000s and wish to delay the sunsetting of that investment.
As the need for grid-edge visibility and control has increased for electric utilities, and the business case for water and gas AMI has improved, these utilities are increasingly looking to leverage the latest AMI technology to catch up to their early adopting peers.
For utilities in this stage of strategizing, planning, and seeking regulatory approval, there can be a strong sense of urgency but also unique hurdles that must be accounted for.
Prior to detailed planning, it’s critical for a utility to align on their corporate strategy to understand if – and how – AMI advances their operations, customer experience vision, regulatory, and over-arching financial objectives. Due to the broad and ever-expanding capabilities directly and indirectly enabled by AMI, most utilities find that the investment is aligned with these objectives. When the ever evolving and expanding demands of grid/distribution management and operations are considered, AMI is increasingly viewed as an essential investment and building block.
Once it’s understood how AMI fits in as an enabler to the utility’s vision at a high level, the next step involves engaging with leadership, key personnel, and internal stakeholders across the organization to align on more specific goals and guiding principles. This includes the desired qualitative and quantitative benefits the utility seeks to realize through a successful program and the specific benefits and value to be realized by customers.
Thorough technology education and evaluation sessions set a strong foundation for the planning process. When assessing traditional (e.g., point to multi-point or “PtMP”, mesh) and emerging (e.g., cellular, LoRa) network structures, evaluate the implications of the service territory’s topography and the pros and cons of each network type.
Technology evaluation is particularly critical for water or shared commodity utilities and service territories with challenging topography that may require unique network designs. For example, mesh networks typically worsen battery life constraints for water and gas utilities, whereas electric endpoints are not battery-powered and thus can benefit from the self-healing network design. Similarly, topographic considerations should be introduced for high-level propagation impacts during planning and detailed propagation study during vendor selection.
Ownership structures should be weighed during the platform assessment, as building a private network will require additional resourcing (but can be capitalized), whereas a managed service (e.g., network as a service, shared network) reduces labor but is typically considered an operating expense.
This technology evaluation informs the roles and systems required to support a deployment of this scale and provides a baseline knowledge for utility personnel.
The benefits and associated costs to enable them must then be captured and modeled within a detailed and accurate business case structure. There are typically internal approvals and gates required to pass through for an AMI investment, making the initial business case development internally facing. But it’s important to construct the business case with an external audience and level of scrutiny involved, including regulator and external stakeholder evaluation.
Develop an initial business case based on known operational data (age of metering assets, nature of cost structure, etc.) and industry benchmarks to identify the estimated return on investment (ROI) of a holistic AMI program. This business case should assess all associated costs over the lifetime of the associated assets, including (but not limited to) internal support requirements, hardware and labor needs for deployment and ongoing maintenance, IT spend (software, hardware, services), network deployment and maintenance, and materials and programs that drive employee and customer outreach, education, and training.
Support requirements should consider the internal and external efforts required to support network build and full business/field deployment as well as long-term program management, such as data analysts, project management, and operational roles (e.g., retraining field resources).
As a rule of thumb, if a particular element of operations is not impacted by the deployment, the team should find out why.
Similarly, the business case should quantify and qualify all associated benefits enabled by the program investment. Manual meter reading benefits are not the sole justifier of an AMI deployment, with many utilities improving outage management, enhancing customer service offerings, and improving system management through sensing and control capabilities (e.g., grid monitoring, theft / tampering identification, leak detection).
It’s critical to introduce the core team of AMI stakeholders, finance, and regulatory affairs to the business case tool methodology early so foundational logic/output structure can be adjusted as needed, vetting business case assumptions across departments. Conduct several iterations of the initial business case to confirm stakeholders understand inputs and outputs, are comfortable with assumptions, and understand how scenario modeling impacts deployment costs and savings.
While many possible permutations of AMI exist at the onset of an evaluation, several key scenarios and decision pathways will likely emerge for consideration and pursuit during the business case and planning states. These scenarios require insight to the various technology options, the inherent capabilities, and how these capabilities will fit into the utility’s target outcomes.
Figure 1 simplifies a decision between three hypothetical AMI program pathways. Scenario 3 may represent a lower cost technology solution which enables a minimal set of outcomes directly. In this case, the example benefit-to-cost ratio of 0.9 indicates that quantified costs exceed quantified benefits. The Base Case represents the highest hypothetical benefit to cost ratio equal to 1.5, indicating benefits expected to be 50% higher than costs. This could represent a more costly technology, system, or process investment than Scenario 3, while also enabling a greater set of target benefits to be achieved. Scenario 2 has higher benefits than the Base Case, though it comes at a higher cost to achieve and diminishes the overall benefit to cost ratio. There may be circumstances in which Scenario 2 would be preferred if there are greater qualitative benefits or regulatory drivers.
Beyond evaluation of known costs and benefits, business case analytics (such as outcome probability assessment and sensitivity analysis) enable a more holistic understanding of the key drivers and risks influencing the business case. Figure 2 shows the hypothetical impact of participation rates and the demand impact of both residential and commercial customers engaged with AMI enabled rates offered by the utility. In this case, a 50% change in the estimated participation levels of residential customers actively changing their usage habits in response to rate options could impact the overall business case net present value by $9.5 million. With the residential estimates, it also drives move overall impact potential to the BCA than the commercial specific estimates over the same uncertainty ranges.
When considering the uncertainty ranges of multiple (or all) input variables together and the impact on BCA financials, utilities can leverage other advanced analytics tools to understand a fuller picture of risk or upside potential. Monte Carlo simulations are a common tool to evaluate outcome probability across deployment scenarios and should be considered as a foremost tool to build internal and external confidence in financial planning. In particular, these tools can be used to support the internal approval process to move forward with AMI planning, understanding the risk profiles of alternative solutions.
Following internal approvals, utilities may elect to move forward with the vendor selection or, depending on the regulatory environment, may require commission or council approval in advance of any procurement activities. When the regulatory avenue is available, vendor bids serve to solidify and support business case projections in the filing process. When seeking vendor bids, utilities should release a competitive request for proposal (RFP) for all associated vendors (e.g., AMI network, installation vendor, meter data management system, customer portal, etc.).
The RFP should include service level agreement (SLA) commitments that transition directly to contract language. The RFP should also require a detailed propagation study that accounts for utility-owned assets, permitting requirements, and other considerations. If contracted installation labor is included in the RFP, utilities should consider proposing contractual mechanisms for the vendor to perform onsite repairs to reduce unnecessary truck rolls and hand-offs. Throughout the planning and selection process, utilities and any professional services should remain completely vendor agnostic until final bids have been proposed. This allows internal stakeholders to maintain an open mind and vendors to sharpen their pencils in pursuit of industry-leading pricing and warranties. Contractual commitments should be bound through any required approval processes (e.g., Commission, City Council) and used to update the business case based on received bids and the preferred vendor.
The utility should plan for ongoing internal communications and cohesive change management plans throughout the effort. Change management must begin in the strategy and planning stage, and ongoing communication and outreach plans and action steps should be designed and initiated across key stakeholder groups:
While risk management is a critical piece of deployment activities, utilities are in a unique position to mitigate program risk at the planning and regulatory stage.
In many service territories, such as those overlapping with utilities whose AMI programs encountered significant challenges, customer opposition is a reality – albeit not an unavoidable one. Comprehensive customer education and outreach campaigns enable utilities to communicate the customer benefits of AMI and to dispel common myths, such as metering accuracy concerns stemming from system-wide replacement of aged hardware.
Network build and management often poses another challenge, particularly for smaller utilities who may consider enhanced resource management (e.g., data analysts to manage the influx of events, alarms, and data) or pursuing a NaaS or cellular contract to reduce management responsibilities. The success of installation vendor management and quality assurance is firmly rooted in the planning and pre-contracting processes.
AMI programs, when planned correctly, realize value far beyond the operational exchange of manual versus automated meter reading. Now more than ever, utilities are expected to articulate how they plan to leverage AMI to benefit customers, enhance operations, and drive enterprise value as part of their internal approval processes as well as being a key component of their filings and regulatory approval process.
Regulatory approval is certainly a key initial goal, but more importantly, by following a thorough strategic alignment and planning process from the outset, utilities will be positioned to drive sustained success and benefit realization in the execution of their AMI programs.
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